This invention relates to electric power utility networks including generating systems, transmission systems, and distribution systems serving loads. The power flowing on these networks is primarily in the form of alternating current and as such is familiar to those skilled in the art.
To remain competitive, electrical utility companies continually strive to improve system operation and reliability while reducing costs. To meet these challenges, the utility companies are developing techniques for increasing the life of installed equipment, as well as, diagnosing and monitoring their utility networks. Developing these techniques is becoming increasingly important as the size and demands made on the utility power grid continue to increase.
A utility power grid is generally considered to include both transmission line and distribution networks for carrying voltages greater than and less than about 25 kV, respectively.
Referring to FIG. 1, a portion of a utility power network is shown to include a transmission network 10 having generators 12, substations 14, and switching stations 16, all of which are interconnected via transmission lines 18. Transmission lines 18, in general, carry voltages in excess of 25 kilovolts (kV). With reference to FIG. 1, the voltage on a particular transmission line is approximately proportional to the thickness of the associated line in the figure. The actual transmission system voltages are indicated in the accompanying key located at the lower right.
Referring to FIG. 2, an exploded portion 10a of the utility power network of FIG. 1 includes distribution lines 20 coupled to a transmission line 18 through step-down transformers 22. Each distribution line carries power to loads 24 at voltage levels less than those levels associated with transmission lines (e.g., 25 kV or less).
Voltage instability on the utility power grid is a critical problem for the utility industry. In particular, when a fault occurs on the transmission grid, momentary voltage depressions are experienced, which may result in voltage collapse or voltage instability on the grid.
To better understand the dynamics of a fault on a utility power system, the sequence of events on the system due to a 3-phase fault on the transmission system will now be described. For example, referring again to FIG. 1, assume the fault occurs on a portion of the transmission network remote from a segment 70. Segment 70 lies between a substation 14a and a switching station 16a of transmission network 10. Referring to FIG. 3, the voltage profile as a function of time at substation 14a due to the fault is shown. In this particular case, the voltage drops from a nominal 115 kV to about 90 kV. It is important to appreciate that if the fault were to occur more closely to segment 70 or on the segment itself, the drop in voltage is generally much more severe, and the voltage on the line can approach zero.
In general, such a fault appears as an extremely large load materializing instantly on the transmission system. In response to the appearance of this very large load, the transmission system attempts to deliver a very large current to the load (the fault). Detector circuits associated with circuit breakers on the transmission system detect the overcurrent situation immediately (i.e., within a few milliseconds.) Activation signals from the detector circuits are sent to protective relays, which initiate opening of the circuit. The nature of the relays generally requires 3-6 AC line cycles (i.e., up to 100 millisecs) to open. When the breakers open, the fault is cleared. However, opening of the breakers triggers a sequence of cascading events, which in the extreme can cause voltage on that portion of the transmission and distribution system to collapse. Specifically, when the breakers open, the voltage is still low (i.e., almost zero) and, because a portion of the transmission system has in effect been removed, the impedance of the system dramatically increases causing the appearance of an artificially high load. In this state the voltage is depressed and the current serving the load sharply increases. The sharp increase in the current generates enormous losses in the transmission and distribution systems. In some cases, because the load and impedance is so high, the voltage on the grid may not return to normal, causing long-term voltage depression and the possible voltage collapse of the entire system. The potential for these voltage instability problems is further exacerbated as load requirements on the grid increase.
Reactive volt-amperes are expressed in VARs; a term coined from the first letters of the words “volt amperes reactive.” Reactive volt-amperes considered over a period of time represent oscillations of energy between the source and the load. Their function is to supply the energy for establishing magnetic fields and charging capacitors, and to transfer this energy back to the source when the magnetic field collapses or when the capacitor discharges.
Note that the reactive power is due to quadrature components of voltage and current and as such represents no average real power. Although reactive volt-amperes, as such, require no average energy input to the generators their existence does consume a certain amount of generator volt-ampere capacity and thereby limits the available real power output of the generators. In addition, there is a resistive or I2R loss associated with the transfer of reactive power over the grid. This additional loss must also be made up by the generator and further limits the real power available to the grid. Note that although the I2R loss is caused by the transfer of reactive power, it is not part of the reactive power.
One approach for addressing the voltage stability problem discussed above is to construct additional transmission lines, reducing system impedance and thereby negating the effects of the high losses and sharp increase in current flow caused by the opening of the breaker. However, providing such additional lines is expensive and in certain settings extremely difficult.
Various equipment and device solutions have also been developed to address these voltage instability problems. In general, such devices provide mitigation by injecting real and/or reactive power into the system.
One such device, called the static VAR compensator (SVC), provides reactive power from a bank of capacitors when a fault is experienced at a particular load. In particular, the SVC rapidly shifts the phase angle of the reactive power from the bank of capacitors, thereby raising the voltage on the network. The SVC continuously shifts the phase angle in response to dynamic power swings on the transmission network due to changing system conditions.
Other devices including batteries and superconducting magnetic energy storage (SMES) differ from SVCs in that they can provide real as well as reactive power to loads. For example, a SMES stores electrical energy provided from the grid in a magnetic field generated by a DC current flowing through a coiled superconducting wire. An approach for using a SMES is to provide power to the load in response to a detected fault after the load is isolated from the grid. Because the SMES, like a battery, is a DC device, a power conditioning system is generally required in order to interface it to an AC utility grid. Thus, the power conditioning system generally includes DC/AC converters as well as other filtering and control circuitry.